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SPE Complex Reservoir Fluids III: Focusing on Reservoir Fluids from the Middle East

15 – 17 September 2014

Dubai, UAE | Hilton Dubai Jumeirah Resort

Technical Agenda

Monday, 15 September

Session 1: H2S—Origin and Management

Session Chairs: Francois Montel,Total; Nicolás Grippo,Dubai Petroleum

This session aims to cover the various aspects of H2S management. In Middle East reservoirs, H2S is the result of Thermo-Sulphato Reduction of anhydrite. Many other sulphur components are produced at the same time. These components are reactive and the speciation of sulphur compounds involves a lot of chemical reactions that affect reservoir conditions, and during production.

Sampling and analysis of sulphur components is subject to many traps and the composition is often not reliable. Therefore, chemical and phase equilibria modelling are necessary to control the concentrations of various components and to reconstruct the in-situ values from limited and altered data. Sulphur deposits may occur during sour gas production—the complexity of the speciation is challenging but necessary for mitigating this issue. Sour gas processing is a mature technology and most operating problems are due to poor evaluation of the initial concentration of H2S and mercaptans, and their evolution with time.

H2S can be seen as a source of sulphur, as a fuel or as a miscibility agent. Significant accumulations worldwide could contribute to fulfilling the increasing energy demand and to feed the thiochemical industry but there is a strong need for innovative and safe technology. H2S management requires many different skills and a perfect knowledge of the thermodynamics and the chemistry of all sulphur compounds in a wide range of pressure and temperature conditions.

Session 2: Gas Injection for EOR

Session Chairs: Dengen Zhou, CVX; John Lawrence, ExxonMobil

This session focuses on the complex reservoir fluid behaviour resulting from gas injection, including acid and nitrogen injection. Gas injection has long been used by the petroleum industry to improve hydrocarbon recovery. In the United States alone, some publications list over 100 current gas injection EOR projects. Gas injection represents a significant opportunity, both globally and in the Middle East, for increasing hydrocarbon liquids recovery. Acid gas and nitrogen injection are particularly relevant due to their ready availability.

Gas injection also covers a wide range of injectants which can be used for a variety of recovery processes. Some of the injectants include CO2, hydrocarbon gas, H2S, N2, flue gas, and mixtures of those gases. The recovery processes can range from gas cycling to improve productivity and condensate recovery, and immiscible injection to improve gravity drainage or vaporisation, to miscible gas injection for enhanced oil recovery.

Any of these fluids or processes can have a profound impact on the phase behaviour and fluid properties of a producing resource. Gas injection can result in complex phenomena such as the formation of multiple liquid phases, asphaltene precipitation, and transition from liquid to vapour. Even at a basic level, the alteration of reservoir fluid densities, viscosities, and interfacial tension, has an important impact on fluid flow in a reservoir. Understanding and accurately predicting the phase behaviour and fluid properties for gas injection processes form the foundation to successful execution of gas injection projects.

Session 3: Reservoir Fluids in Carbonate Systems

Session Chairs: Norman Kaczorowski,OXY; Shahin Negahban, ADCO

Accurate predictions of the complex PVT behaviour of petroleum fluids are vital in reservoir simulations and field development studies including complex pilots performance interpretations, full field rates and reserves predictions (a requisite for full-field development projects) and, ultimately, history matching and reservoir management of full-field projects. The complexity and prediction of the PVT properties becomes considerably more complex when considering EOR pilots and full-field development projects.

Complex reservoir fluids characterisation is a challenging task both experimentally and in EOS modelling, particularly, if the reservoir conditions are close to the fluids mixture critical point and EOR injectants cause asphaltene precipitation (subsequent asphaltene flocculation and deposition and require more complex thermodynamic models, such as PC SAFT, for PVT property prediction). Experimentally, correct fluid samples planning and acquisition, samples validation, laboratory programme elaboration and quality check of experimental data are all important contributing factors to reliable fluid characterisation. The correct description of the phase behaviour can be challenging and requires significant attention and expertise given its potential impact on field development planning, well performance, and reservoir management strategies.

This session presents papers on fluid characterisation of complex carbonate reservoirs, considering many key issues such as identification of key fluid uncertainties, fluid sampling, laboratory programme, validation of experimental data, fluid characterisation and modelling, assessment of the impact on field development planning, and the impact on reservoir management strategy.

Session 4: Breakout Session

Tuesday, 16 September

Session 5: Mobility-Challenged Fluids/Unconventional Resources

Session Chairs: Birol Dindoruk, Shell; Tao Yang, Statoil

Historically, we have been more used to heavy/viscous fluids. However, in recent years, there has been an added dimension to the complexities encountered in reservoir fluids where the fluid phase behaviour is affected by pore proximity (i.e. shales and nano-darcy systems). Also a wide spectrum of fluids discovered in such environments result in an increase in the compositional complexity. Furthermore, some of the suggested analysis techniques in literature are considered to be non-predictive because of lack of good experimental data to prove them. Produced/discovered fluids range from lean/dry gases (acid gases/sweet gases, etc.) to extra heavy oils and bitumens. One of the interesting facts of the mobility-challenged fluids is that we already know where the major deposits are, yet we are not able to unlock their potential. As the fluids, the reservoir conditions (high temperature, high pressure deep water discoveries at paleogene), and the dimensions related to the porous media or the fabric of the porous media become more and more challenging, so does the progress in the computational area; for e.g., new EOS models (including pore proximity effects) and fit-for-purpose computational techniques, advanced characterisation methods, etc.

This session focuses on complex reservoir fluid behaviour in unconventional resources where we generalise their behaviour in terms of their mobility while the challenges that we face might be due to different fundamentals. However, the general outcome from the reservoir performance management point of view is the same or very similar—low rates/recoveries. This challenge is due to either the character of the rock (i.e. shales), or due to the viscosity of the oil (i.e. heavy/extra heavy oils) or, perhaps the worst, which is the combination of both.

This session is designed to stimulate discussions about the impact of fluid phase behaviour in terms of recovery processes and as well as the reservoir initialisation. Some of the key questions are as follows:

What kind of fluids do we have in the reservoir and can we sample them efficiently?

How would the fluid properties change spatially and/or over time?

What is really important for excellent reservoir performance?

Is pore-proximity effect a myth or reality in terms of recovery processes and what would be the criteria with which to rate its importance?

What are the forces that we need to overcome for the production of mobility-challenged fluids?

How can we compute/predict the behaviour of these fluids?

What is the current state of affairs in terms of computational techniques for mobility-challenged fluids?

What would be the next generation or future (EOS/non-EOS) computational techniques?

Session 6: Geochemistry Tools for Compartmentalisation and Allocation

The recognition of reservoir heterogeneities responsible for field compartmentalisation is a key issue to reach production targets and to prevent or reduce expenses involved by unrecognised barriers to fluid flow. Molecular fingerprinting techniques may detect fluid discontinuities within and between reservoirs of the same field, even with genetically related oils. The same approach can be used for allocation purposes. Natural tracers have been used for quantitative allocation. The selected tracers must not be sensitive to reservoir and production conditions and the tracer ratio differences can be converted into well-stream production ratios. Integration of geochemistry and thermodynamics is the key for successful application of these techniques.

Sampling and conditioning versus in-situ measurements will be addressed during the workshop. Monitoring the field with natural tracers is an emerging technology, and combined with compositional reservoir modelling, it provides new insights into the complex fluid behaviour in hydrocarbon traps.

Round-Table Discussion: The Bridge Between Molecular and Macro-Scale: Validation of Coarse-Grained Molecular Representation

Moderators: Dengen Zhou, CVX; Francois Montel,Total

An evolution towards practical molecular-based models seems inevitable in order to work with fluid behaviour description in reservoir modelling. Such a new paradigm in our industry, compared to adhoc correlations, is the only way to reach a unique fluid representation for all thermodynamic and transportation properties. Furthermore this molecular-based representation would enable us to efficiently take into account the complexity introduced by the porous medium in fluid behaviour. Our challenge is to create a link between molecular scale results, and effective fluid properties in porous media, at reservoir scale. To reach such a goal, we have to rely on a bottom-up approach based on a combination of simulations and modelling at different scales. A review of the limitations and capability of the various techniques are necessary.

The microscopic scale corresponds to the atomistic level that can be described using Molecular Simulation methods. However, such simulations are still time-consuming and limited to submicrometer systems. Hence, they cannot be used alone and should be coupled with up-scaled modelling when dealing with larger scales.

New EOS like SAFT are based on a coarse-grained molecular representation. The parameters can be validated by direct molecular simulation. It creates a frame within which to build the link between nano and macro scales, when dealing with thermodynamic quantities. A review of the new SAFT EOS is also required to help our community focus on a single variant. All other fluid representations for practical use should be consistent with the original model. The translations are often incorrect or inconsistent.

Session 7: Multidisciplinary Integration and Fluid Management

SessionChairs: Curtis H. Whitson, PERA; Yun Wang, BP

This session will address the challenges of characterising fluid streams for applications in different disciplines using different software tools. Fluid characterisation underpins the understanding of multi-phase fluid flow both in porous media in the subsurface, and in flow lines and processing facilities away from the subsurface, as the fluid flow is heavily influenced by the phase behaviour and fluid properties under these varied conditions. Even though the need for fluid characterisation is common among the different applications in the subsurface and beyond, there is no consensus on a common approach for characterising fluids for different disciplines, nor is there a common platform tool for fluid characterisation.

This session is designed to stimulate robust discussions about the best practices that the industry adopts to characterise hydrocarbon fluids for different disciplines. This session can help address a number of interesting questions related to this topic.

For instance, do we routinely collect PVT data covering a wide range of pressures, temperatures and compositions for a variety of applications, such as reservoir engineering, flow assurance and process engineering? When we develop fluid characterisation for solid phase onset (hydrates, wax, asphaltenes, etc.), what data besides onset conditions do we include for calibrating fluid characterisation? When we develop fluid characterisation for sour fluids, do we have robust data for H2S partitioning in liquid, vapour and aqueous phases over a wide range of pressures, temperatures, compositions, and water ionic compositions and pH values? Do we frequently develop a reference “truth” Equation of State (EoS) fluid characterisation from which different versions of fit-for-purpose EoS descriptions can be derived for different disciplines? Do we always generate PVT tables from an underlying EoS fluid characterisation so that there is consistency across different disciplines? How do we ensure that the compositional ranges considered in the subsurface models over the life of the field, are properly captured in the modelling of steady state and transient multi-phase flow downstream of the subsurface? What are the best practices of navigating the multiple modelling tools that have different phase behaviour and fluid property calculation functionalities?

In addition to fluid characterisation, this session will feature discussions about hydrocarbon fluid sampling from a multidisciplinary integration point of view. Participants will discuss the different ways to design a robust fluid sampling programme so that there is enough sample volume with sufficient sample quality to cover laboratory analysis for different disciplines.